Drillstring motion analysis and control

ABSTRACT

Apparatus, systems, and methods may operate to obtain acceleration data from an operational drillstring, decompose the acceleration data into one or more empirical modes, monitor the amplitude of at least one of the empirical modes to detect indications exceeding a preselected threshold, and modify drillstring operational parameters comprising at least one of rotational speed, weight on bit, or mud flow, based on the indications. Additional apparatus, systems, and methods are disclosed.

BACKGROUND INFORMATION

A number of undesirable conditions can develop while drilling a borehole. For example, standing vibration waves can be generated along the drillstring, leading to a condition known as stick/slip. In this condition, the drillstring stops rotating for a period of time, and then spins free. The resulting instantaneous rotation frequency can be high enough to loosen the coupling between drillstring elements. Another condition is known as whirl, in which the bit, or a portion of the drillstring, rotates around the circumference of the borehole (instead of substantially centered within the borehole). This can quickly become a chaotic phenomenon in which the drillstring seems to randomly bounce back and forth, slapping against the sides of the borehole. These conditions, and others, can result in reduced drilling efficiency, and may even cause the drillstring to become stuck in the borehole.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates accelerometer signal modal decomposition according to various embodiments of the invention.

FIG. 2 illustrates apparatus that operates to decompose accelerometer signals according to various embodiments of the invention.

FIG. 3 illustrates systems according to various embodiments of the invention.

FIG. 4 is a flow chart illustrating several methods according to various embodiments of the invention.

FIG. 5 is a block diagram of an article according to various embodiments of the invention.

DETAILED DESCRIPTION

Time series measurements made using accelerometers and other motion-sensitive sensors can be used to diagnose undesirable vibration phenomena that occur as part of drilling operations. Because of inter-related effects, a reliable diagnosis can be difficult to make when several phenomena exist simultaneously. However, if enough motion-sensitive sensors are used, along with instrumentation for real-time standoff measurements, the various modes of drillstring motion can be isolated by combining the sensor outputs. Unfortunately, due to constraints on funding and computer resources, this type of operation is not practical.

As an alternative, a mechanism is disclosed herein that permits identifying various modes of vibrational motion presented by a bottom hole assembly (BHA) using a single measurement vehicle (e.g., a single accelerometer). By deriving modal decomposition information from surface or downhole (or both) acceleration sensors, and identifying/correlating the behavior of the modes with specific downhole phemonena, operational drilling parameters can be modified to reduce or eliminate undesirable vibration that has been identified.

In some embodiments, the entire analysis may be carried out downhole and used to stabilize a downhole drilling motor, a rotary steerable device, an adjustable blade stabilizer, a controllable shock sub, and other components having functions that affect drillstring operational parameters. The operations disclosed can be carried out in a higher-dimension space to incorporate a plurality of measurements.

The phenomenon of stick/slip will be used to illustrate the teaching of this disclosure. It should be noted, however, that the various embodiments are not to be so limited. Any vibrational phenomenon that can be identified via substantially repetitive behavior when analyzed using empirical mode decomposition is included.

FIG. 1 illustrates accelerometer signal modal decomposition according to various embodiments of the invention. In this case, a sequence of signal data is shown in graph 100, as acquired from a single downhole accelerometer attached to a drillstring while the drillstring was operating in a stick/slip mode. The hesitation of the drillstring is clearly visible in graph 100 at time intervals centered around 0.7 seconds, 3 seconds and 5.1 seconds. Because of the shortness of the time interval, the temporal and spectral resolution for a conventional spectrogram (e.g., using Fourier analysis) would be relatively poor.

The empirical mode decomposition of signals is well known to those of ordinary skill in the art. For example, computer-implemented empirical mode decomposition as applied to luminance in digital camera images is described in detail in U.S. Pat. No. 6,311,130, incorporated herein by reference in its entirety. The empirical “modes” into which accelerometer signal data are decomposed herein are equivalent to the Intrinsic Mode Functions (IMF's) described in U.S. Pat. No. 6,311,130, and are indicative of intrinsic oscillatory modes in the physical phenomenon to be studied (e.g., drillstring vibration).

When the original signal shown in graph 100 is decomposed into empirical modes, the results can be seen in graphs 102 (mode-1), 104 (mode-2), 106 (mode-3), 108 (mode-4), 110 (mode-5), and 112 (mode-6). The residue, without bias, is shown in graph 114.

Modes 1 and 2 (i.e., graphs 102, 104) represent high frequency events that are likely not related to stick/slip. Mode 3 (i.e., graph 106) represents a process that starts at about 1 second, dies down at about 2.5 seconds, and restarts at about 3 seconds. As with the base waveform (shown in graph 100), the process appears to be substantially repeatable, although this is not always the case. Mode 4 (i.e., graph 106) represents a more or less continuous mode upon which the stick/slip has been superimposed. The base waveform signal that results from continuous drilling represented in graph 100 can be represented by the sum of modes 4, 5, 6 and the residual (i.e., graphs 108, 110, 112, and 114).

The breakdown of a signal into empirical modes has the advantage that, at least ideally, and typically as a good approximation, the modes represent what are called analytic signals, which can be represented by a time-domain amplitude function and a time-domain phase function, where the phase increases monotonically with time. That is, a mode (e.g., any one of modes mode-1 through mode-6) can be expressed in the form:

M(t)=Re[A(t)*e ^(i*Θ(t)))],

where Re designates the real part of the enclosed function, A(t) is the amplitude of the mode M(t) as a function of time, i=√{square root over (−1)} and Θ(t) is the phase of the mode as a function of time. Ideally, A(t) is a positive definite function and Θ(t) undergoes no reversals over time. This form of expression makes it possible to define the instantaneous frequency (the Hilbert frequency) as the time derivative of the phase:

${\omega (t)} = {\frac{{\Theta (t)}}{t}.}$

As shown in graph 106, the amplitude 130 of one or more of the modes (in this case, mode-3) can be monitored continuously for excursions above a pre-set threshold 120. For example, a downhole or surface computer can keep track of the average of the amplitude 130 over some selected period of time and compare the values of the current amplitude 130 with this average (which may be a running average, such as an exponential average, among others). The threshold can be at some fixed value, or a fixed amount above the average, or expressed as a band substantially centered on the average. Alternatively, a pre-defined threshold amplitude, such as threshold 120, can be transmitted from the surface to the downhole tool using any available measurement while drilling (MWD) downlink communications channel.

When an anomalously high amplitude is detected, such as where the threshold is exceeded by the amplitude 130 of mode-3 at points 122, 124, 126, and 128, the amplitude and the mode number can be relayed to surface equipment, perhaps along with information about the number of high amplitude events, the mean separation in time between such events, the instantaneous frequency during the time period when the amplitude exceeded the threshold 120, an average of the instantaneous frequency during the time period when the amplitude exceeded the threshold 120, etc. This information is sufficient for the driller to identify that the angular rate at which the rotary table turns needs to be changed and for the driller to determine how it needs to be changed. The calculated amplitude can also be compared with that obtained using various drillstring dynamics modeling programs, thus providing a calibration point for the drillstring dynamics program that has been selected for use, while the program itself is used to select a different rotary speed.

It is noted that in this case mode-1 and mode-2 (i.e., graphs 102, 104) contain information about the shock spectrum of the downhole instrumentation that has been modally decoupled from the stick/slip motion. If other modes of motion had been present, it is expected that they would also be separated out by the modal analysis. It can also be noted that the modal decomposition analysis can be accomplished without recourse to Fourier techniques, and that, in comparison, Fourier techniques often provide a less complete picture of the phenomenon, because they cannot provide the frequency resolution in short time intervals that is usually possible with modal decomposition apparatus and methods.

FIG. 2 illustrates apparatus 200 that operates to decompose accelerometer signals according to various embodiments of the invention. Here it can be seen that the signals from one or more accelerometers 284 can be acquired using a data acquisition system 260, which feeds the signals, perhaps after amplification and filtering, into an analysis module 262. The analysis module 262, in turn, may be used to decompose the accelerometer signals into empirical modes.

The signal characteristics of the raw accelerometer signals and/or the derived empirical modes (e.g., amplitude, polarity, phase, etc.) may be monitored by a monitoring module 264 to determine whether the current empirical mode signal values exceed some selected threshold, perhaps established as an absolute threshold, or as a relative threshold (e.g., a threshold riding at some distance, absolute or relative, above and/or below a running mean of the acquired amplitude). For example, a change of more than ±10% or ±20% from a running mean of the empirical mode signal amplitude values.

The accelerometer signals, the mode amplitude values, the mode instantaneous frequency values, and indications of the threshold being exceeded can all be transmitted from downhole to the surface 204 for further processing. It should also be noted that any of the components shown below the surface 204, as part of the apparatus 200 may be located at the surface 204. Similarly, components shown as part of a logging station 292 and located at the surface 204 may be located downhole, perhaps attached to a BHA, which may serve to reduce the use of high data rate telemetry techniques on a particular project. Thus, many embodiments may be realized.

For example, an apparatus 200 may comprise an analysis module 262 to decompose acceleration data provided by an accelerometer 284 attached to a drillstring into at least one empirical mode. In some cases, only one empirical mode will be evident, with the residue comprising random noise. The apparatus 200 may also comprise a monitoring module 264 to monitor the amplitude of one or more empirical modes, and to provide indications of the amplitude exceeding a preselected threshold.

Thus, the apparatus 200 can be used to measure acceleration of the drillstring, or some component attached to the drillstring, decompose the data into empirical modes, and monitor the behavior of modal data. The apparatus 200 can be located on the surface 204, downhole, or various components of the apparatus 200 may be divided between the two locations.

In some embodiments, a receiver 266 can be used to receive various parameters from the surface 204, such as the threshold used by the monitoring module 264. Thus, the apparatus 200 may comprise a receiver 266 to receive a preselected threshold from a surface source (e.g., the logging station 292), where the receiver 266 can be coupled to the monitoring module 264 (e.g., via the analysis module, as shown in FIG. 2).

The analysis module 262, the monitoring module 264, or both, may be housed in a downhole tool 224. Thus, the apparatus 200 may comprise a downhole tool 224 to at least partially house at least one of the analysis module 262 or the monitoring module 264.

A processor 254 can be used to further process modal data, perhaps to determine the amplitude of empirical modes as a function of time, and/or to maintain a running average of the amplitudes. Thus, the apparatus 200 may comprise a processor 254 to derive the amplitude of one or more empirical modes and/or to display a variety of information about modal behavior on the display 296. The processor 254 can be at least partially housed by the downhole tool 224 as well.

As noted previously, a transmitter 268 can be used to send many different types of information to the surface 204. For example, the apparatus 200 may comprise a transmitter 268 to transmit one or more amplitudes, running averages of amplitudes, the number of indications of one or more amplitudes exceeding one or more corresponding thresholds per unit time, or the mean separation time between the indications. In some embodiments, the transmitter 268 can be used to transmit an alert message to the surface 204, with a display of the alert message content based on the amplitude. In this way, anomalous amplitude events might be used to initiate an alarm, perhaps used to stop drilling operations.

FIG. 3 illustrates systems 300 according to various embodiments of the invention. The system 300 may comprise more than one of the apparatus 200. Thus, the apparatus 200, as described above and shown in FIG. 2, may form portions of a down hole tool 224 as part of a downhole drilling operation.

Turning now to FIG. 3, it can be seen how a system 300 may also form a portion of a drilling rig 302 located at the surface 204 of a well 306. The drilling rig 302, comprising a drilling platform 386 may be equipped with a derrick 388 that supports a drill string 308 lowered through a rotary table 310 into a wellbore or borehole 312.

Thus, the drill string 308 may operate to penetrate a rotary table 310 for drilling the borehole 312 through subsurface formations 314. The drill string 308 may include a Kelly 316, drill pipe 318, and a BHA 320, perhaps located at the lower portion of the drill pipe 318. The drill string 308 may include wired and unwired drill pipe, as well as wired and unwired coiled tubing, including segmented drilling pipe, casing, and coiled tubing.

The BHA 320 may include drill collars 322, a down hole tool 224, and a drill bit 326. The drill bit 326 may operate to create a borehole 312 by penetrating the surface 204 and subsurface formations 314. The down hole tool 224 may comprise any of a number of different types of tools including MWD tools, logging while drilling (LWD) tools, and others.

During drilling operations, the drill string 308 (perhaps including the Kelly 316, the drill pipe 318, and the BHA 320) may be rotated by the rotary table 310. In addition to, or alternatively, the bottom hole assembly 320 may also be rotated by a top drive or a motor (e.g., a mud motor) that is located down hole. The drill collars 322 may be used to add weight to the drill bit 326. The drill collars 322 also may stiffen the BHA 320 to allow the bottom hole assembly 320 to transfer the added weight to the drill bit 326, and in turn, assist the drill bit 326 in penetrating the surface 204 and subsurface formations 314.

During drilling operations, a mud pump 332 may pump drilling fluid (sometimes known by those of ordinary skill in the art as “drilling mud” or simply “mud”) from a mud pit 334 through a hose 336 into the drill pipe 318 and down to the drill bit 326. The drilling fluid can flow out from the drill bit 326 and be returned to the surface 204 through an annular area 340 between the drill pipe 318 and the sides of the borehole 312. The drilling fluid may then be returned to the mud pit 334, where such fluid is filtered. In some embodiments, the drilling fluid can be used to cool the drill bit 326, as well as to provide lubrication for the drill bit 326 during drilling operations. Additionally, the drilling fluid may be used to remove subsurface formation 314 cuttings created by operating the drill bit 326.

Thus, referring now to FIGS. 1-3, it may be seen that in some embodiments, the system 300 may include a drill collar 322, a drill string 308, and/or a down hole tool 224 to which one or more apparatus 200 are attached. The down hole tool 224 may comprise an LWD tool, or an MWD tool. The drill string 308 may be mechanically coupled to the down hole tool 224. Thus, additional embodiments may be realized.

For example, a system 300 may comprise a drillstring 308, one or more accelerometers 284 attached to the drillstring 308, and one or more apparatus 200, as described previously. In some embodiments, the system 300 comprises a display 296 to present rotational activity of the bit 326 coupled to the drillstring 308, perhaps based on the amplitude of one or more of the empirical modes, and the indications of the one or more modes exceeding some selected threshold. In this way, the drillstring 308 and/or bit 326 activity can be displayed to the rig operator, perhaps in graphic form.

Depending on the specific implementation, various components of the system 300 may be attached to the downhole tool 224. Thus, the system 300 may comprise a downhole tool 224, wherein at least one of the analysis module or the monitoring module (see elements 262, 264, respectively in FIG. 2) are attached to the downhole tool 224.

A control system 398 can be used to modify drilling operations based on the data obtained by monitoring the empirical modes. Thus, a system 300 may comprise a control system 398 to modify drillstring operational parameters comprising one or more of the rotational speed, weight on bit, or mud flow based on the indications (of exceeding a selected threshold). One or more displays 296 may be included in the system 300 as part of a processor 254 in a logging station 292 to display any type of acquired data, including the raw acquired accelerometer data, empirical mode data (amplitude and/or phase), threshold data, etc.

The apparatus 200, downhole tool 224, processor 254, data acquisition system 260, analysis module 262, monitoring module 264, receiver 266, transmitter 268, accelerometers 284, logging facility 292, system 300, drilling rig 302, drill string 308, rotary table 310, Kelly 316, drill pipe 318, bottom hole assembly 320, drill collars 322, drill bit 326, mud pump 332, drilling platform 386, derrick 388, and control system 398 may all be characterized as “modules” herein. Such modules may include hardware circuitry, one or more processors and/or memory circuits, software program modules and objects, and firmware, and combinations thereof, as desired by the architect of the apparatus 200 and system 300, and as appropriate for particular implementations of various embodiments. For example, in some embodiments, such modules may be included in an apparatus and/or system operation simulation package, such as a software electrical signal simulation package, a power usage and distribution simulation package, a power/heat dissipation simulation package, and/or a combination of software and hardware used to simulate the operation of various potential embodiments.

It should also be understood that the apparatus and systems of various embodiments can be used in applications other than for borehole drilling and logging operations, and thus, various embodiments are not to be so limited. The illustrations and descriptions of apparatus 200 and systems 300 are intended to provide a general understanding of the structure of various embodiments, and they are not intended to serve as a complete description of all the elements and features of apparatus and systems that might make use of the structures described herein.

Applications that may include the novel apparatus and systems of various embodiments comprise process measurement instruments, personal computers, workstations, and vehicles, among others. Some embodiments include a number of methods.

For example, FIG. 4 is a method flow diagram 411 according to various embodiments of the invention. Thus, a method 411 may begin at block 421 with obtaining acceleration data from an operational drillstring. For example, as noted above, acceleration data may be obtained from a single accelerometer. Thus, the activity at block 421 may include obtaining the acceleration data from a single accelerometer attached to the drillstring.

The method 411 may continue on to block 425 with decomposing the acceleration data into one or more empirical modes. In many embodiments, the empirical modes comprise one or more modes having a dominant frequency of about 0.2 Hz to about 500 Hz.

The method 411 may include monitoring the amplitude of the one or more empirical modes at block 429, perhaps to detect indications exceeding a preselected threshold (as determined at block 437). Thus, if a threshold has not been previously selected, or if the threshold is to be changed, the method 411 may include determining the preselected threshold at block 433 based on a running average of the amplitude of one or more modes, to detect excursions beyond normal operation. In some embodiments, the activity at block 433 includes receiving the preselected threshold (downhole) from a surface location.

If the indications do not exceed the threshold, as determined at block 437, then the method 411 may return to block 421 to obtain additional accelerometer data. However, if the indications are determined to exceed the selected threshold, as determined at block 437, then the method 411 may continue on to block 441 with determining an average time between the indications. This is because the average time between indications that exceed the selected threshold can help determine what type of activity is occurring with the drill string and/or bit (e.g., stick/slip or whirl).

Depending on the number, amplitude, and frequency of the indications received, the rig operator can be informed of the vibrational modes that might be in existence along the drill string, or at the drill bit. Alternatively, or in addition, the activity can be stored in a log for later use. Thus, the method 411 may go on to include, at block 445, publishing a report comprising one of stick/slip, bit bounce, whirling, or lateral vibration based on the indications. The method 411 may go on to block 449 to include modifying drillstring operational parameters comprising at least one of rotational speed, weight on bit, or mud flow, based on the indications.

In this way, the method 411 may include acquiring acceleration data, decomposing the data into one or more empirical modes, monitoring the amplitude of at least one of the modes, and modifying drillstring operations responsive to the amplitude behavior. For example, the activity at block 449 may include reducing the rotational speed until the number of the indications per unit time falls below a selected frequency. In cases of whirling, for example, it may be the best practice to reduce the rotational speed. The activity at block 449 may additionally, or alternatively include increasing the rotational speed until a number of the indications per unit time falls below a selected frequency. For example, in some cases of resonant behavior, such as stick/slip, it may be beneficial to increase the rotational speed beyond the resonant condition.

Dynamic phenomena, such as stick/slip, whirl, bit bounce, and lateral vibration, can be identified using the apparatus and systems described herein, or as part of the disclosed methods. After individual phenomena have been identified, various embodiments can sometimes operate to correct them, or at least, to reduce their intensity, perhaps by varying the rotational bit speed, weight on bit, and/or mud flow.

For example, stick/slip can be identified by the sudden appearance of a mode that has non-zero amplitude at approximately zero frequency for a period of time that is a significant fraction of what, in the short-term history of the drillstring, was the average period revolution.

Those of ordinary skill in the art are aware that at least two types of whirl exist: bit whirl and collar whirl. Conceptually, they are the same, but practically, they may have a different impact on the overall drillstring operation, since the bit and collars are typically located at different points of the drillstring.

The onset of whirl may follow the appearance of a mode with an instantaneous frequency close to (or equal to) a harmonic of the rotational frequency, perhaps as determined by the historical output of one or more rotationally sensitive transducers. As whirl worsens, there is typically a doubling or tripling of the frequency of the first mode that has appeared. Several such modes may be present simultaneously. When the most destructive level of whirl has been reached, the progression of harmonic modes breaks down completely—these modes suddenly disappear and are replaced by random impulse noise.

Due to whirl's nature (the bit or the drill collars rolling around the inside of the borehole wall), it is possible to have negative frequencies (i.e., rotating clockwise or counter-clockwise). Unlike the negative frequencies that may arise as an output of a Fourier Transform analysis, these negative frequencies indicated by a modal analysis are physically significant.

If only one sensor is used, the negative frequencies will appear as positive frequencies in a modal decomposition. However, when two or more sensors are used (e.g., two orthogonal accelerometers), experimental results as a function of time indicate that a correlation of the outputs of these sensors can be used to determine the direction (i.e., sign) of the modal frequencies.

When an experiment is designed so that only one mode is present, the modal decompositions of the two signals are, in essence, the signals themselves. The direction of rotation can be determined by calculating an angle defined as the four quadrant arctangent of the x- and y-signals provided by the orthogonal sensors, where the x-signal is provided by one sensor, and the y-signal is provided by the other. If the x- and y-signals are of different magnitudes, they can be rescaled to be of the same magnitude. The direction of rotation is then determined by the change between samples of the rotation angle. Since the arctangent is a discontinuous function, there are some samples where the direction of rotation can not be determined. One of ordinary skill in the art will realize that there are yet other ways of ascertaining the direction of rotation from the two sensor outputs, or from modes of the two sensor outputs.

There is another type of whirl phenomena that is known as “synchronous whirl.” In this type of whirl, the drillstring is generally in contact with the borehole wall. This may by accompanied by slipping, but normally occurs in a direction opposite to that of the drillstring rotation. Under such conditions, it may be useful to use a different type of sensor to identify the modes. In particular, one or more bending moment sensors can be used to produce signals indicative of the bending stress along the drillstring. Fourier analysis or modal analysis can be used to establish the presence of regular frequencies in the bending stress signals. Two or higher dimensional analyses similar to those discussed above can also be carried out with the bending moments.

A subspecies of synchronous whirl is one in which the same side of the drill collars or of the bit continually faces or rubs against the borehole wall. In this case, a significant level of bending will be present at the same time that all modes have diminished to a value of approximately zero.

Bit bounce includes a significant random component. However, some portions of the bit motion along the drillstring axis can still exhibit modal behavior. A first example is when roller cone bits are used: as the formation is broken up by the bit, a regular pattern develops in the bottom of the borehole. This pattern, created by the motion of the bit, also contributes to drillstring motion of the bit. The pattern typically continues to deepen until the depth contrast of the pattern is equal to (or somewhat less than) the relief across the face of the bit, at which time the bit operates to destroy the pattern. While the pattern grows, drillstring bit vibration increases. When pattern destruction occurs, drillstring axis bit vibration decreases. This is described in SPE 14330-MS Field Measurements of Downhole Drillstring Vibrations, Wolf, S. F., Zacksenhouse, M., Arian, A., 1985.

Bit bearing failure will modify the vibrations along the drillstring axis near the bit since a dragging cone scrapes the formation, instead of crushing it. When this happens, a change in the bit bounce vibration mode will be evident. In addition, stalling may be evident, as indicated by sensors responding to vibrations orthogonal to the drillstring axis or by rotation-sensitive sensors. This might seem to be similar to stick/slip, but because stick/slip is a standing wave phenomenon, the associated frequencies usually fall within a well-defined, reasonably predictable range. Hence, the signature of a dragging bit would be a sudden change in the normal mode of drillstring-axis vibration coupled with a broad-band modal behavior with frequencies that fall outside of the frequencies expected for stick/slip.

The predicted approximation of drillstring vibrational behavior provided by a drillstring dynamics modeling program according to the torque load, formation type, weight on bit, borehole shape, surface rotational speed, and other factors can be adjusted to match the measured vibrational behavior represented by the indications. Thus, in some embodiments, the method 411 includes calibrating a drillstring dynamics modeling program used to select a rotary speed of the drillstring, based on the indications (perhaps as used to identify the various phenomena), at block 453.

The activity of the bit and/or drillstring may be graphically displayed, depending on the monitored mode activity. Thus, the method 411 may include displaying rotational activity of the borehole bit attached to the drillstring based on the amplitude of one or more monitored modes, and the indications (of exceeding a selected threshold).

Bit steering operations may also be adjusted according to the monitored mode indications. Thus, the method 411 may include steering the borehole bit along a path based on feedback associated with the indications, at block 461. For example, it may turn out that steering in a particular direction to enter a softer formation type operates to lessen vibrations indicating stick/slip conditions.

Of course, this assumes that due consideration is given to normal drilling operations, so that feedback to “correct” the operation is not provided when observed events correlate to desired formation penetration activities. For example, it may be useful to cross a bed boundary at an angle that is not-orthogonal to the boundary, such as when drilling through an anisotropic formation—perhaps purposely drilling along an axis where the rock/bit interaction causes a deflection of the drill bit from the desired direction. In these circumstances, a mode of vibration orthogonal to the drillstring, and a mode along the drillstring can develop that together reflect the instantaneous velocity of the bit, which changes continuously and somewhat repetitively during each rotation of the bit until the bit has cleared the boundary. Thus, in this case, the feedback associated with various indications may be modified.

It should be noted that the methods described herein do not have to be executed in the order described. Moreover, various activities described with respect to the methods identified herein can be executed in iterative, serial, or parallel fashion. Information, including parameters, commands, operands, and other data, can be sent and received, and perhaps stored using a variety of tangible media, such as a memory. Any of the activities in these methods may be performed, in part, by a digital electronic system (e.g., a digital computer), an analog electronic system (e.g., an analog control system), or some combination of the two.

Upon reading and comprehending the content of this disclosure, one of ordinary skill in the art will understand the manner in which a software program can be launched from a computer-readable medium in a computer-based system to execute the functions defined in the software program. One of ordinary skill in the art will further understand that various programming languages may be employed to create one or more software programs designed to implement and perform the methods disclosed herein. The programs may be structured in an object-orientated format using an object-oriented language such as Java or C++. Alternatively, the programs can be structured in a procedure-orientated format using a procedural language, such as assembly, FORTRAN or C. The software components may communicate using any of a number of mechanisms well known to those skilled in the art, such as application program interfaces or interprocess communication techniques, including remote procedure calls. The teachings of various embodiments are not limited to any particular programming language or environment. Thus, other embodiments may be realized.

For example, FIG. 5 is a block diagram of an article 585 according to various embodiments of the invention. The article 585 comprises an article of manufacture, such as a computer, a memory system, a magnetic or optical disk, some other storage device, and/or any type of electronic device or system. For example, the article 585 may include one or more processors 587 coupled to a computer-accessible medium 589 such as a memory (e.g., fixed and removable storage media, including tangible memory having electrical, optical, or electromagnetic conductors) having associated information 591 (e.g., computer program instructions), which when executed by a computer, causes the computer (e.g., the processor(s) 587) to perform a method including such actions as obtaining acceleration data from an operational drillstring, decomposing the acceleration data into at least one empirical mode, monitoring the amplitude of the at least one empirical mode to detect indications exceeding a preselected threshold, and modifying drillstring operational parameters comprising at least one of rotational speed, weight on bit, or mud flow based on the indications. The data may be acquired using a single accelerometer. Additional actions may include, for example, determining the preselected threshold based on a running average of the amplitude, or receiving the preselected threshold from a surface location. Indeed, any of the activities described with respect to the various methods above may be implemented in this manner.

Implementing the apparatus, systems, and methods of various embodiments may provide the ability to detect abnormal drilling conditions, diagnose them, and provide a controller with the appropriate parameters to correct the situation—all from data acquired using a single accelerometer. Improved drilling efficiency, and lower drilling costs, may result.

The accompanying drawings that form a part hereof, show by way of illustration, and not of limitation, specific embodiments in which the subject matter may be practiced. The embodiments illustrated are described in sufficient detail to enable those skilled in the art to practice the teachings disclosed herein. Other embodiments may be utilized and derived therefrom, such that structural and logical substitutions and changes may be made without departing from the scope of this disclosure. This Detailed Description, therefore, is not to be taken in a limiting sense, and the scope of various embodiments is defined only by the appended claims, along with the full range of equivalents to which such claims are entitled.

Such embodiments of the inventive subject matter may be referred to herein, individually and/or collectively, by the term “invention” merely for convenience and without intending to voluntarily limit the scope of this application to any single invention or inventive concept if more than one is in fact disclosed. Thus, although specific embodiments have been illustrated and described herein, it should be appreciated that any arrangement calculated to achieve the same purpose may be substituted for the specific embodiments shown. This disclosure is intended to cover any and all adaptations or variations of various embodiments. Combinations of the above embodiments, and other embodiments not specifically described herein, will be apparent to those of skill in the art upon reviewing the above description.

The Abstract of the Disclosure is provided to comply with 37 C.F.R. §1.72(b), requiring an abstract that will allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. In addition, in the foregoing Detailed Description, it can be seen that various features are grouped together in a single embodiment for the purpose of streamlining the disclosure. This method of disclosure is not to be interpreted as reflecting an intention that the claimed embodiments require more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive subject matter lies in less than all features of a single disclosed embodiment. Thus the following claims are hereby incorporated into the Detailed Description, with each claim standing on its own as a separate embodiment. 

1. An apparatus, comprising: an analysis module to decompose acceleration data provided by an accelerometer attached to a drillstring into at least one empirical mode; and a monitoring module to monitor an amplitude of the at least one empirical mode to provide indications of the amplitude exceeding a preselected threshold.
 2. The apparatus of claim 1, further comprising: a receiver to receive the preselected threshold from a surface source, the receiver to couple to the monitoring module.
 3. The apparatus of claim 1, further comprising: a downhole tool to at least partially house at least one of the analysis module or the monitoring module.
 4. The apparatus of claim 1, further comprising: a processor to derive the amplitude of the at least one empirical mode.
 5. The apparatus of claim 4, wherein the processor is at least partially housed by a downhole tool.
 6. The apparatus of claim 1, comprising: a processor to maintain a running average of the amplitude.
 7. The apparatus of claim 1, comprising: a transmitter to transmit at least one of the amplitude, a running average of the amplitude, a number of the indications per unit time, a mean separation time between the indications, or an average of an instantaneous frequency during a time period when the amplitude exceeds the preselected threshold.
 8. The apparatus of claim 1, comprising: a transmitter to transmit an alert message to the surface, the alert message based on the amplitude.
 9. A system, comprising: a drillstring; an accelerometer attached to the drillstring; an analysis module to decompose acceleration data provided by the accelerometer into at least one empirical mode upon rotation of the drillstring; and a monitoring module to monitor an amplitude of the at least one empirical mode to provide indications of the amplitude exceeding a preselected threshold.
 10. The system of claim 9, comprising: a display to present rotational activity of a bit coupled to the drillstring, based on the amplitude and the indications, in graphic form.
 11. The system of claim 9, comprising: a downhole tool, wherein at least one of the analysis module or the monitoring module are attached to the downhole tool.
 12. The system of claim 9, further including: a control system to modify drillstring operational parameters comprising at least one of rotational speed, weight on bit, or mud flow based on the indications.
 13. A method, comprising: obtaining acceleration data from an operational drillstring; decomposing the acceleration data into at least one empirical mode; monitoring an amplitude of the at least one of the empirical mode to detect indications exceeding a preselected threshold; and modifying drillstring operational parameters comprising at least one of rotational speed, weight on bit, or mud flow based on the indications.
 14. The method of claim 13, further comprising: calibrating a drillstring dynamics modeling program used to select a rotary speed of the drillstring, based on the indications.
 15. The method of claim 13, further comprising: determining an average time between the indications.
 16. The method of claim 13, wherein the modifying comprises: reducing the rotational speed until a number of the indications per unit time falls below a selected frequency.
 17. The method of claim 13, wherein the modifying comprises: increasing the rotational speed until a number of the indications per unit time falls below a selected frequency.
 18. The method of claim 13, wherein the obtaining comprises: obtaining the acceleration data from a single accelerometer attached to the drillstring.
 19. The method of claim 13, wherein the at least one empirical mode comprises: a mode having a dominant frequency of about 0.2 Hz to about 500 Hz.
 20. The method of claim 13, further comprising: publishing a report comprising one of stick/slip, bit bounce, whirling, or lateral vibration based on the indications.
 21. The method of claim 13, comprising: displaying rotational activity of a borehole bit attached to the drillstring based on the amplitude and the indications.
 22. The method of claim 13, comprising: steering the borehole bit along a path based on feedback associated with the indications.
 23. An article including a computer-accessible medium having instructions stored thereon, wherein the instructions, when accessed by a computer, result in the computer performing: obtaining acceleration data from an operational drillstring; decomposing the acceleration data into at least one empirical mode; monitoring an amplitude of the at least one empirical mode to detect indications exceeding a preselected threshold; and modifying drillstring operational parameters comprising at least one of rotational speed, weight on bit, or mud flow based on the indications.
 24. The article of claim 23, wherein the instructions, when accessed, result in the computer performing: determining the preselected threshold based on a running average of the amplitude.
 25. The article of claim 23, wherein the instructions, when accessed, result in the computer performing: receiving the preselected threshold from a surface location. 